There are a number of textbooks available that describe the processes involved in drilling for oil and gas. Examples of such textbooks are “Petroleum Well Construction” by Economides, Watters and Dunn-Norman, John Wiley & Sons, West Sussex, UK, 1998; “Applied Drilling Engineering” by Bourgoyne, Jr., Chenevert, Millhelm and Young, Jr., SPE Textbook Series, Vol. 2, Society of Petroleum Engineers, Richardson, Tex., 1991; or “Drilling Technology—In Nontechnical Language” by S. Devereux, PennWell Corp., Tulsa, Okla., 1999. Reference may be made to these textbooks for an understanding of general drilling processes.
A drilling operation suitable for implementing the present invention is shown in FIG. 1. The drill rig 10 drives a drill string 11, which is composed of a large number of interconnected sections 30, called pipe joints. The bottom of the drill string is composed of heavy-weight pipe sections 13, called drill collars. In a typical drilling operation, the rig rotates the drill string and thus the bottom hole assembly (BHA) 14. The BHA 14 may contain various instrumentation packages, possibly a mud motor or a rotary-steerable system, stabilizers, centralizers, drill collars and the drill bit 15. The drill string and all downhole components are hollow, allowing drilling fluids to be pumped from the surface to the bit, with the drilling fluid returning to the surface in the outer annulus between the drill string and the formation for cleaning and re-circulation. The drill string 11 may contain additional sections of heavy-weight drill pipe and/or specialized equipment such as drilling jars.
The two most common drive systems are the rotary-table system and the top-drive system. The rotary-table system, shown in FIG. 1, engages the drill string through the kelly bushing 16 and the kelly 17, causing the drill string 11 to rotate while the kelly 17 is free to move up and down as the pipe is lowered into the ground or is lifted from the borehole. As the borehole deepens, pipe joints 30 are periodically added to the top of the drill string 11 by means of rotary shoulder connections that provide mechanical strength and hydraulic seals. A top-drive system does not require a kelly 17; instead, the entire drive mechanism moves up and down with the top end of the drill string 11. A top-drive system facilitates and accelerates the drilling process; however, it is also more expensive than a rotary-table system.
FIG. 2 shows a commonly used pipe joint 30 comprising a “box” tool joint 31 at the top, a long tubular section 32 and a “pin” tool joint 33 at the bottom. A typical length for a pipe joint is 31 ft. (about 9.5 m), but deviations of around +/−1 ft. are commonplace. Both pin 33 and box 31 are equipped with conical threads 34 that, when joined, form a rotary connection. The two primary purposes of the connection are the transmission of mechanical forces such as torque, tension and compression between pipe joints 30 and to provide a liquid-tight metal-to-metal seal at the outer shoulders 35. The connection is typically made-up using pipe tongs or motorized spinners, a process that puts the pin 33 under tension, the box 31 under compression and the metal seal interface shoulders 35 also under compression. This compressional seal load must exceed the tensional loads the seal 35 experiences during bending and flexing in the hole to keep the metal-to-metal seal intact. The interior walls of the pipe joint 30 may be coated with a high-performance epoxy compound. This compound is a high-quality dielectric insulator that inhibits corrosion of the metallic pipe and reduces friction losses in the fluid. Commercially available examples of such pipe coating compounds are “TK-236” or “TK-34”, both available from Tuboscope, Tex., Houston, U.S.A.
The downhole instrumentation packages contained in the BHA 14 collect information about the drilling process, about the formations being drilled, and about the fluids contained in those formations. In current practice, most of this data is stored in downhole memory and later retrieved after the instrumentation has been brought back to the surface. A very small and compressed amount of information, however, is typically sent in real time to the surface using one of the currently available mud-pulse telemetry systems. Such systems induce pressure pulses within the drilling fluid column contained by the drill string to convey a digital signal to the surface at rata rates of around 0.1-15 bits/sec. However, the amount of information available in real time through a mud-pulse system is inadequate by far for today's complex drilling operations that require accurate, real-time borehole data.
Commercially viable reservoirs tend to be much more complex than those exploited in the past and the recovery rates of the oil or gas in place must be constantly increased to make the remaining hydrocarbon reservoirs last longer. This also means that well trajectories can no longer be fully pre-planned based on seismic data or data from offset wells. Instead, well trajectories are more and more determined and fine-tuned while a hole is being drilled. To accomplish this task, formation evaluation data must be brought to the surface and must be studied and interpreted while drilling is progressing. The interpretation results may or may not require adjustments to the well trajectory, which are communicated back to the rig site. The rig equipment in turn communicates these adjustments to the downhole equipment. An example for a downhole imaging device that generates large amounts of formation evaluation data while a hole is being drilled is described in “Field Testing of an Advanced LWD Imaging Resistivity Tool,” by Prammer et al., SPWLA 48th Annual Logging Symposium, Austin, Tex., 2007. Since the drilling process is relatively slow and formation data can be compressed by the downhole electronics, a transmission rate along the drill string of about 100-10,000 bits/second (bps) is required. In addition, the command channel from the surface to the downhole instrumentation and the drilling system requires from time to time a transmission rate of approximately 10-1,000 bps.
A need to transmit data from a downhole location reliably has been recognized for a very long time. For a discussion of previous attempts to solve this difficult problem, reference is made to PCT/US2009/00449949, filed May 22, 2009. The contents of this application are hereby incorporated by reference in their entirety.
Application PCT/US2009/00449949, filed May 22, 2009 describes a telemetry system based on coupling elements and transmission elements buried within the fusion-bonded epoxy (FBE) coating often applied to the inner bore of high-performance drill pipe for corrosion protection. These elements transmit radiofrequency signals that bridge the gap between pipe joints based on capacitive/dielectric coupling. The coupling mechanism is dissipative, requiring each pipe joint to contain an active signal repeating element.
A commercial system known as “IntelliPipe” or “IntelliServ”, described in, for example, U.S. Pat. No. 6,670,880 to Hall et al., is termed a “wired pipe” system (“WPS”) because signals are conveyed via armored coaxial cable deployed in the inner bore of the drill string. Details of the Hall WPS can be found in “Very High-Speed Drill String Communications Network, Report #41229R14,” June 2005, by D. S. Pixton, DOE Award Number DE-FC26-01NT41229, available from the website of the U.S. Department of Energy at www.doe.gov.
As discussed above, a drill string is made up of a multitude of pipe joint segments, which are each typically about 30-32 ft. long and which are joined together by rotary connections. The Hall WPS takes advantage of special, high-performance connections, known as double-shouldered rotary tool joints. Double-shouldered tool joints are machined to exacting specifications such that mating tool joints not only engage at the outer, sealing shoulder, but also at an inner shoulder formed by the flat face of the pin 33 and the flat back wall of the box 31. The Hall WPS uses these secondary contact surfaces to house ferrite-based ring-shaped magnetic couplers that transmit electromagnetic signals from one segment of armored coaxial cable contained in a first pipe joint to the cable segment contained in the neighboring pipe joint. When the WPS rotary joints are made-up, pairs of embedded coupling elements form closed circuits of high magnetic permeability, i.e. ferrite-core transformers. The transmitted signal is attenuated as it travels along the drill string through a multitude of cable segments and transformers and needs to be periodically reconditioned and brought back to full signal strength. These tasks are performed by repeater subs that are inserted in the drill string at regular intervals that range between approximately 1,000 ft.-2,000 ft.
The transformers in the Hall WPS are based on brittle ferrite core material. The ferrite half-cores protrude from the face of the joint pin and from the back wall from the joint box. During the make-up operation, facing ferrite half-cores are expected to rotate against each other and to force each other into the face of the pin and into the box back wall, respectively. Since the ferrite half-cores need to move in and out of the pin face and the box back-wall, respectively, it is not possible to hermetically seal the couplers from the environment. The intense downhole pressure of up to 30,000 psi (approximately 200 MPa) forces drilling fluid into and behind the couplers. The drilling fluid carries and lodges solid particulates such as sand, barite, metal filings and/or drilling chips of any size behind the ferrite cores, thereby jamming them and inhibiting their retraction. Once a ferrite core is stuck in the protruding position, it will be destroyed by the full compressional force exerted during the make-up operation. However, commercial drill pipe is expected to withstands hundreds to thousands make-up/break-out cycles under harsh and dirty conditions, a number that is not attainable if the pipe contains fragile, exposed components subject to repeated, abrasive action such as those experienced by the Hall WPS ferrite transformers.
Furthermore, drill pipe is routinely exposed to mechanical shocks during normal drill rig operations. For example, during rig-down, individual pipe joints slide down an inclined ramp from the rig floor to the ground, where, at the end of the ramp, the pipe segments slam into a stopping board. When the pipe is hoisted vertically in the rig, it frequently and violently slams down on the metallic rig floor and/or on other rotary connections. Any of these common impacts that ordinary drill pipe is expected to withstand can cause open or concealed damage to the Hall couplers that are exposed on the pin face. A compromised Hall coupler, although apparently still functional during checkout under atmospheric conditions on the surface, is likely to break under the combined action of high temperature, very high pressures and the aggressive fluids found in downhole conditions. Furthermore, since the Hall transformers are moving parts and therefore are not hermetically sealable, their electrical connections and the interior O-ring seals are subjected to the corrosive action of the drilling fluids, causing electrical and mechanical degradation and breakdowns simply by accumulating downhole hours.
A goal of the present invention is a data transmission system that uses non-moving, hermetically-sealed signal couplers that are compatible with the harsh conditions of drilling operations at the surface and underground.
The fundamental WPS reliability problem has been widely recognized; see, for example, U.S. Pat. Appl. 2004/0217880 A1 by Clark et al. Clark et al. calculate that for a 15,000 ft. long WPS to exhibit a desirable mean time between failure (MTBF) of about 500 hours, each of the wired-drill pipe components much achieve an MTBF of at least about 250,000 hours (28.5 years). Such an MTBF is unrealistic for most electromechanical systems, let alone downhole systems containing moving parts such as the Hall couplers. Clark et al. disclose a system for troubleshooting a failed WPS. However, the very fact that such systems fail frequently and require often and labor-intensive troubleshooting intervention renders them unsuitable for use under the harsh and rushed conditions of oil and gas drilling.
A goal of the present invention is a wired-pipe data transmission system that achieves good reliability over its entire design lifetime and that can be built from individual components with reliability values that are typical of electrical components operating under harsh downhole conditions.
Another goal of the present invention is a data transmission system that fails gradually, allowing the continuation of drilling operations, while simultaneously the failure is detected, diagnosed and reported to an operator, who may choose to replace the pipe segment containing the failed element at the next opportunity. Such opportunities exist when the drill string must be removed from the hole, because of, e.g., a worn-out drill bit or a change in borehole diameter.
Existing wired-pipe systems rely on repeater subs that periodically refresh the transmitted signal. These highly-complex subs, of which 10-20 are needed per drill string, constitute a large capital expense burden and consume large amounts of typically “Size D” primary lithium cells as their power source. These large-size lithium batteries are expensive to manufacture and pose a fire hazard during transport, operation and disposition. Another goal of the present invention is the replacement of these expensive and dangerous repeaters with small and inexpensive elements that are safe to handle, to store and to transport.